A comparative study of brine solutions as completion fluids for oil and gas fields

Completion fluids play a vital role in well-related processes within the oil extraction industry. This article presents a comprehensive study of the properties and performance of various brine solutions as completion fluids for different well and reservoir conditions. Attributes examined include density, corrosion resistance, temperature stability, compatibility with formation fluids, clay swelling potential and influence on wettability. The research highlights the significance of selecting appropriate completion fluids to optimize well and reservoir operations. Zinc chloride emerges as an excellent option for high density applications, while sodium chloride and potassium formate solutions are ideal for extreme cold conditions. Potassium acetate outperforms calcium chloride and potassium chloride and has excellent pH stability. The compatibility of completion fluids with formation water has been observed to be excellent, with no sedimentation or emulsion formation. Potassium acetate also experiences minimal clay swelling, making it suitable for clay-rich formations. On the other hand, calcium chloride has a higher clay swelling than most of the brines tested, making it less suitable for sandstone formations with a higher clay content than these brines. The research evaluates the water-wetting abilities of completion fluids in carbonate and sandstone formations. Potassium chloride and zinc chloride have the most significant impact in carbonate formations, while potassium acetate and potassium formate excel in sandstone formations. This study provides a comprehensive understanding of completion fluids, facilitating informed decisions that maximize operational efficiency, protect reservoir integrity, and enhance hydrocarbon recovery. The appropriate selection of completion fluids should align with specific well and reservoir conditions, considering the priorities of the application.

corrosion caused by formate fluids significantly increased; so they designed a corrosion system with anti corrosion additives that overcomes this problem; but they didn't investigate the effect this system has on formation damage and ignored other types of fluids 24 .In 2020, Tariq et al., introduced a completion fluid additive known as polyoxyethylene quaternary ammonium gemini surfactant, which effectively prevents clay swelling.They conducted experiments involving core flood sandstone cores with a high clay content and compared the results to potassium chloride and sodium chloride solutions.But they did not compare it to formate based solutions.They also didn't conduct any experiments on the corrosion or the change in wettability caused by the completion fluids.The findings indicate that flooding with a sodium chloride solution led to an 80% reduction in permeability, while potassium chloride resulted in a 38% reduction.In contrast, the gemini surfactant solutions did not significantly decrease permeability 25 .In 2022, Avula et al., prepared three fluids based on potassium formate with varying weights and assessed their rheological properties at different temperatures.They discovered that because of its optimal characteristics, 60% w.l.potassium formate based fluid could be better suited for drilling, completion or workover applications.However, they conducted no experiments on the effect this concentration has on formation damage; they also ignored other types of fluids 26 .In 2022, Ahmed Khan et al., performed several core flood experiments on chloride based and ionic fluid based completion fluids by using Scioto sandstone core samples, but no experiments were conducted on organic based ones.There were also no experiments done on the corrosion or wettability change caused by the completion fluids.They concluded that unlike the chloride based completion fluids, the ionic based completion fluid caused almost no reduction in permeability 27 .
As can be seen from existing literature, although several studies have been conducted on common brines, none of these studies have been conducted on many brines under the same experimental conditions.Furthermore, the mechanisms of formation damage have either not been explored or have not been comprehensively investigated in prior research.To address this gap, a comparative analysis presented in Table 1

Brine
In this study, brines of zinc chloride, calcium chloride, potassium chloride, sodium chloride, potassium acetate, and potassium formate, each with specific densities and pH levels, have been meticulously prepared.Table 2 below provides an overview of the characteristics of these brine solutions.

Thin physical samples
As depicted in Fig. 1, thin physical samples of carbonate and sandstone, each measuring 0.08 inches in thickness, were meticulously prepared to assess the wettability alterations induced by the completion fluids.

Corrosion coupons
Steel samples crafted from L80 alloys were employed for the corrosion evaluation.The characteristics of these steel samples are detailed in Table 3.

Formation fluid
In this study, formation water and crude oil were collected from an oil and gas field in southern Iran for experiments.These samples were gathered from various wells within the field and transported to the laboratory under   www.nature.com/scientificreports/controlled conditions.Subsequently, the samples underwent filtration, stabilization, and were stored in suitable containers for further analysis.The ionic constituents of the formation water and crude oil were determined using standard methods and instruments, including ion chromatography, gas chromatography, and mass spectrometry.
The results are presented in Tables 4 and 5, respectively.

Density
Oil and gas reservoirs typically operate under high temperature and pressure conditions, necessitating the use of heavy-weight completion fluids to balance the fluid's hydrostatic pressure and the reservoir pressure.However, the required weight of the completion fluid varies based on the reservoir's depth.For shallow reservoirs with high pressure, a heavy and costly completion fluid (exceeding 100 pounds per cubic foot) may be essential.Conversely, for deeper reservoirs, medium-weight completion fluids with a lower cost might suffice, as the hydrostatic pressure on the reservoir increases with depth 4 .The density of a brine is determined by the type and concentration of the salt it contains.In this section, fluid density is measured using a pycnometer in accordance with ISO 13503-3-2006.This method entails weighing the pycnometer with the fluid, subtracting the weight of the empty pycnometer, and then dividing by the volume of the pycnometer 28 .

Corrosion
In oil and gas well operations, the integrity of well structures is paramount.Corrosion tests are essential to evaluate the potential impact of completion fluids on well construction materials, such as L80 steel.The primary quality of a completion fluid is its non-corrosive nature, as brines, commonly used as base fluids, can induce corrosion, posing risks to wellbore pipes and equipment 24,[29][30][31][32] .The corrosion testing procedures delineated in this section are conducted in strict adherence to the comprehensive guidelines specified in API RP13 standards.The testing sequence commences with the meticulous measurement of the L80 steel coupon's weight, employing a precision scale with four decimal places.Subsequently, the density and pH levels of the completion fluid are meticulously ascertained.Following these initial measurements, the completion fluid is combined with the coupon, and the entirety is positioned within a dedicated corrosion cell.This specialized cell subsequently undergoes placement within an oven set to an exacting temperature of 149 °C.Moreover, the cell is subjected to a pressure environment reaching 2.76 MPa, and the incubation period extends over a span of 72 h.Upon the conclusion of this exposure period, the cell is painstakingly opened, facilitating the careful separation of the completion fluid from the steel coupon.This sequence culminates with a comprehensive cleaning process of the coupon, followed by the recalibration of its weight.Ultimately, the extent of corrosion induced by the completion fluid is meticulously quantified, expressed in millimeters per year, utilizing the precise mathematical Eq. (1) 33 .

Temperature stability
Temperature stability is a critical aspect when evaluating the performance of completion fluids.Both low-and high-temperature stability tests are conducted to ensure that these fluids maintain their integrity under varying conditions.

Low temperature stability
Low-temperature stability testing aims to determine the crystallization temperature of brine.This temperature marks the point at which solids begin to form.These solids can take the form of ice crystals (due to the freezing of water) or salt crystals precipitating because of reduced solubility.The precipitation of salt crystals not only reduces the solution's density but can also obstruct pipelines, disrupt pumping operations, and clog filtration systems.Furthermore, it poses the risk of diminishing hydrostatic pressure in the brine, potentially leading to fluid loss and well control incidents.In this test, brine samples are carefully placed in a freezer at -10 °C for a duration of 72 h.The test aims to observe the presence or absence of fluid sedimentation and crystallization.

High temperature stability
For wells operating at significant depths, the completion fluids used may undergo precipitation or undergo alterations in their characteristics due to elevated temperatures.These temperature-induced changes can have a significant impact on the requisite attributes of the completion fluid.High-temperature stability tests are carried out to assess the clarity, density, and pH of the fluids under different temperature conditions, allowing for a comparative analysis.The test commences by transferring the selected brines into specially designed glass containers that are resistant to high temperatures and properly sealed to prevent liquid evaporation.The samples are subjected to a range of temperatures, including 25, 40, 60, 80, 100, and 120 °C.After a day at each temperature, measurements are taken to ascertain the density and pH of the samples, providing critical insights into the stability of completion fluids across a spectrum of operating conditions.

Formation damage
Oil and gas wells can suffer from formation damage during any phase of drilling, completion, or stimulation.The formation can be harmed by the fluids that are used for these operations, as they may penetrate into it 8,34,35 .
To avoid or minimize formation damage, it is essential to understand how the completion fluids affect the formation 36 .The completion fluid should have a pH between 7 and 9 because higher pH levels can weaken the sandstone reservoir's structure 27 .This section examines the clay swelling caused by brines, the wettability changes induced by the fluid, and the compatibility of the brine with the formation fluids.

Clay swelling
Clay swelling, a crucial consideration in oil and gas operations, is a phenomenon where water molecules envelop the crystalline structure of clay, causing an expansion in both distance and volume 37 .This expansion can detrimentally affect the permeability of the formation, potentially leading to decreased operational efficiency.In the context of drilling mud and water-based completion fluids, clay swelling is particularly problematic when these fluids infiltrate sedimentary rock formations.Such swelling can disrupt oilfield operations and result in substantial cost implications, making the mitigation of clay swelling a matter of paramount importance 38 .It is notable that clays with higher exchange capacities, such as smectite and their mixtures, exhibit pronounced swelling behavior, especially when situated within the larger pores of reservoir rock.This swelling creates nearly impermeable barriers to fluid flow.In contrast, clays with lower exchange capacities, such as kaolinite, illite, and chlorite, do not swell to the same extent upon hydration 39 .The addition of salt to drilling fluids is a common practice to minimize clay swelling since clay tends to swell more in pure water than in brine [40][41][42] .The objective of this test is to evaluate the extent of clay swelling when exposed to various completion fluids.The procedure adheres to ASTM D5890 standards (ASTM 2006) for consistency and reliability 43 .Thus, the steps to perform the test are as follows: 1. Clay Preparation: Begin by isolating 2 g of bentonite clay powder.2. Completion Fluid Primary: Place 90 cubic centimeters of the selected completion fluid into a 100 cubic centimeter test tube.3. Incremental Clay Addition: Add 0.1 g of the 2 g of separated clay to the completion fluid at 10-min intervals until the clay is entirely hydrated.4. Observation and Comparison: Following clay hydration, transfer a small amount of the completion fluid to an empty container containing the remaining 2 g of clay.Blend this mixture with the fluid from the test tube.5. Volume Measurement: Return the mixture to the test tube, adding completion fluid as necessary to reach a total volume of 100 cubic centimeters.6. Post-Hydration Observation: After a 24-h waiting period, observe and measure the volume of the clay, comparing it to its initial volume.

Wettability alteration
Wettability, or a liquid's ability to stick to a solid surface, depends on a delicate balance between intermolecular interactions that stick (liquid-to-surface) and don't stick (liquid-to-liquid) 44 .The ability of pore surfaces to hold water has a big effect on how different types of fluid move and settle in rock formations below the surface.This has a huge effect on how badly formations are damaged in oil reservoirs.Predicting how wettability will affect formation damage is hard because it changes over time and is affected by interactions between rocks and fluids as well as changes in the conditions of the reservoir 45,46 .Wettability, characterized by contact angles and correlated with surface tension, plays a pivotal role in oil reservoirs.Contact angles between 0° and 70° indicate highly water-wet rocks, while angles ranging from 110° to 180° signify a strong oil-wet nature.Intermediary wettability is attributed to contact angles between 70° and 110°4 7 .This experiment aims to scrutinize the capacity of completion fluids to modify the wettability of reservoir formations, consequently enhancing production yields.
The experimental procedure commences with the transformation of sandstone and carbonate-thin physical samples into oil-wet surfaces.To achieve this, these thin physical samples are immersed in a 0.01 M stearic acid solution and exposed to a temperature of 65.5 °C for 48 h.Following this treatment, the thin physical samples undergo a thorough wash with water and n-heptane.Subsequently, they are delicately positioned on the surface of water, and a droplet of kerosene, administered via a syringe, is dispensed beneath them.The interface of this droplet is meticulously captured through imaging with the assistance of Digimizer software, allowing for precise measurement of the contact angle.In instances where the thin physical samples exhibit an oil-wet disposition, they are introduced to the designated completion fluid and subjected to an aging similar to the previous step.This process is followed by the repetition of the aforementioned steps to ascertain whether these sections have undergone a transformation towards being water-wet or not 4,48,49

Fluid compatibility
In the context of this basin, the notion of fluid compatibility bears substantial importance.Fluid incompatibility surfaces when two fluids, upon their amalgamation, exhibit a tendency to separate into distinct phases or form an emulsion in the presence of salts or other solid constituents.Such incompatibility poses a notable risk of sediment formation within the porous media of the reservoir formation, potentially leading to pore blockage and detrimental formation damage.One of the most renowned instances of fluid incompatibility arises from the interaction of seawater with formation water.The characteristics that define this incompatibility hinge on the stark contrast between their respective ion compositions.Seawater is characterized by a high concentration of sulfate ions coupled with low levels of calcium, barium, and strontium ions.In stark contrast, formation water exhibits the inverse, boasting low sulfate ion concentrations and high levels of calcium, barium, and strontium ions.The outcome of their convergence is the precipitation of compounds such as calcium sulfate, barium sulfate, and strontium sulfate salts, which manifest as undesirable sediments 4,45,50,51 .This section of our study revolves around a comprehensive assessment designed to probe the compatibility dynamics between completion fluids and various formation fluids.Notably, the latter encompasses formation water and crude oil.To scrutinize this intricate interplay, we have devised a series of meticulous experiments.Our aim is twofold: to ascertain the propensity for sediment formation or its absence after the amalgamation of desired completion fluids and diverse formation fluids across varying volume ratios, all subjected to elevated temperatures.The experimental protocol is orchestrated as follows: 1. Preparation of Fluid Mixtures: Completion fluids are meticulously blended with formation fluids in three distinct ratios: 1:1, 1:3, and 3:1. 2. Sealing in Resilient Glass Containers: These precisely concocted fluid mixtures are then carefully transferred to specialized glass bottles, engineered to withstand the rigors of autoclave temperatures.3. Exposure to Elevated Temperatures: The sealed glass bottles, each representative of a distinct fluid mixture, are entrusted to an environment where temperature soars to 80 °C.This arduous environment serves as the crucible for assessments, simulating reservoir conditions in a controlled laboratory setting.4. Post-Exposure Assessment: Following an aging period of 72 h, the samples are delicately extracted from their high-temperature crucible.Diligent examinations are directed towards the identification of sedimentation or the conspicuous absence thereof.
These well-planned experiments give a solid basis for figuring out how well different formation fluids and completion fluids work together.This helps in getting a full picture of the problems and interactions that might happen.Looking at how sediment forms when volume ratios change and temperatures rise helps in understanding how fluid compatibility affects the integrity and performance of reservoirs, which in turn helps in making smart decisions in real-world situations.

Density
The density of brine solutions plays a crucial role in their performance and suitability for a range of oil and gas operations.In this part, the density of different brine solutions was studied at different concentration levels.These solutions included calcium chloride, potassium chloride, sodium chloride, potassium formate, potassium acetate, and zinc chloride.The outcomes are visually depicted in Fig. 2, which effectively illustrates the connection between density and salt concentration for each respective brine solution.
An instructive insight gained from Fig. 2 is the pronounced density of calcium chloride brine relative to all chloride-based brines, with potassium chloride brine trailing in second place.This alignment with established literature reinforces the prevailing use of calcium chloride and potassium chloride as primary medium-density brines in activities related to well completion and workover operations.Moreover, the data reveals that, at a temperature of 25 ℃, potassium chloride brine achieves a higher peak density compared to its sodium potassium chloride counterpart.This finding implies a greater efficacy of potassium chloride in augmenting the density of water-based fluids when compared to sodium chloride.
Equally noteworthy, the data in Fig. 2 unveils an intriguing non-linear relationship between density and salt content for potassium formate and potassium acetate brines, setting them apart from their counterparts, which exhibit a linear behavior.This suggests the ease with which the density of these brines can be adjusted by modifying the concentration of potassium formate and potassium acetate.Furthermore, these brines exhibit moderate densities in contrast to their peers, rendering them particularly suitable for deployment in the context of deep, high-pressure wells.This is especially beneficial as the use of high-density fluids may give rise to formation damage or operational complications in such conditions.However, it is essential to acknowledge the challenges encountered during the course of this study, particularly the procurement of pure zinc chloride salt.The zinc chloride salt utilized in this study contained a noteworthy quantity of impurities, posing an impediment to generating a clear density graph.Despite this challenge, a solution was achieved by dissolving 760 g of zinc chloride in 300 cc of water.The resultant solution initially appeared cloudy but was successfully clarified following a filtration process.This observation indicates the substantial potential of zinc chloride as a high-density brine, a point of considerable significance.

Corrosion
In the context of corrosion testing, a series of comprehensive experiments were conducted at an elevated temperature of 149 °C, focusing on a range of brine solutions.The detailed results of these corrosion tests are meticulously documented in Table 6, providing a comprehensive overview of the corrosion characteristics exhibited by these  www.nature.com/scientificreports/fluids.Additionally, Fig. 3 serves as a visual representation of the transformation in corrosion coupons before and after these rigorous corrosion tests.
A thorough analysis of Table 6 unequivocally reveals that both calcium chloride and potassium acetate exhibit higher corrosion rates compared to the other examined fluids.Intriguingly, calcium chloride demonstrates a notably higher corrosion rate than potassium acetate.In scenarios where corrosion rate is of paramount concern within a well, it becomes apparent that potassium acetate solution presents a more favorable option when contrasted with calcium chloride.In cases where these specific fluids are deemed indispensable for operational requirements, the judicious deployment of corresponding corrosion inhibitors is highly recommended.It is vital to underscore the significance of maintaining the pH of the completion fluid within the optimal range of 7-9.5.This pH range not only plays a pivotal role in corrosion control but also serves as a preventive measure against clay swelling.As elucidated in Table 6, the pH levels of all fluids, except for zinc chloride, steadfastly fall within the recommended pH range of 7-9.5.This observation is particularly remarkable given the fact that zinc chloride, despite its exceptionally low pH and the presence of zinc ions, typically associated with heightened corrosion rates, displays the lowest corrosion rate when juxtaposed with the other tested solutions.It is imperative to acknowledge that potassium chloride and sodium chloride solutions were not subjected to these specific corrosion tests.This decision was based on the extensive body of prior research conducted on these solutions and their distinctly low densities, rendering them unsuitable for inclusion in the current study.

Low temperature stability
In the evaluation of low-temperature stability, a noteworthy distinction emerged among the tested brines.As depicted in Fig. 4, it's evident that potassium acetate, potassium chloride, and calcium chloride brines experienced crystallization at a frigid temperature of -10 °C.This crystallization phenomenon is a crucial consideration as it can potentially lead to blockages in pipelines, interference with pumping operations, and clogging of filtration systems.However, intriguingly, the potassium acetate solution exhibited notably less crystallinity compared to calcium chloride.On the other hand, zinc chloride, sodium chloride, and potassium formate brines demonstrated resilience, showing no discernible signs of precipitation or crystallization under these extreme cold conditions.
These findings underscore the importance of selecting the appropriate brine solutions for specific well conditions, particularly in regions where sub-zero temperatures are encountered.Because potassium acetate is less crystallized than calcium chloride, it is a better choice in these conditions because it is less likely to precipitate and get clogged when temperatures are low.This means that it works more reliably.Additionally, the exceptional stability that zinc chloride, sodium chloride, and potassium formate exhibit, further emphasize their suitability for use in wells where low-temperature stability is a crucial consideration.Their ability to remain free from crystallization at − 10 °C underlines their potential as reliable choices in oil and gas operations that confront extreme cold conditions.

High temperature stability
High-temperature stability is a crucial aspect when assessing completion fluids, especially for wells exposed to elevated downhole temperatures.Figures 5 and 6 present the key findings regarding density and pH changes following high-temperature stability tests.Moreover, Fig. 7 provides visual insights into the outcomes of these experiments for each solution.
In the case of potassium formate brine, the test outcomes are illuminating.The increase in temperature from 25 to 120 °C resulted in a substantial drop in fluid density, reaching as low as 0.037 g per cubic centimeter.The pH also exhibited a noticeable decline within this temperature range, settling around 1. The results highlight the sensitivity of potassium formate brine to high-temperature conditions, with a significant impact on both density and pH.The high-temperature stability tests for calcium chloride brine also showed that its density and pH dropped.It dropped by about 0.034 g per cubic centimeter and had pH shifts that were not good when it was exposed to temperatures between 25 and 100 °C.However, the test at 120 °C faced challenges due to the extreme conditions, resulting in vaporization and unrealistic density values.Nonetheless, Fig. 7 illustrates that the solution remained completely clear despite these harsh conditions.As the temperature increased from 25 to 100 °C, potassium chloride brine showed a decrease in density of less than 0.029 g per cubic centimeter and a pH reduction of roughly 1 pH unit.Significant fluid vaporization hindered the test at 120 °C, as seen in the other brines, making density readings unrealistic.Nevertheless, Fig. 7 demonstrates the brine's ability to maintain clarity under these  www.nature.com/scientificreports/demanding conditions.Sodium chloride brine exhibited the lowest density reduction, approximately 0.025 g per cubic centimeter, as temperatures elevated from 25 to 100 °C.The pH experienced a moderate reduction of 0.4 pH units, with an initial gradual decrease followed by an increase within the 60-120-degree range.Despite facing challenges during the test at 120 °C due to vaporization, Fig. 7 displays the continued clarity of the solution.Contrastingly, the high-temperature stability test for zinc chloride solution unveiled more significant shifts.As the temperature escalated from 25 to 120 °C, the density decreased by approximately 0.066 g per cubic centimeter.Notably, the solution exhibited a color change to bright yellow, signifying the potential issues when employing zinc chloride solution in high-temperature wells.Careful consideration is advised when using this solution under such conditions.The temperature stability assessment of potassium acetate brine revealed unique characteristics.The density decreased to about 0.039 g per cubic centimeter as the temperature climbed from 25 to 120 °C.However, the pH displayed intriguing behavior.It decreased up to 60 °C and, contrary to expectations, increased until reaching 80 °C.Subsequently, as the temperature peaked at 120 °C, the pH decreased to 8.85. Figure 7 visually captures the slight yellowing of the solution as the temperature gradually increased.These observations suggest that potassium acetate solution exhibits higher density loss compared to other solutions, necessitating careful handling in high-temperature well applications.

Clay swelling
The clay swelling tests were performed on five distinct fluids: zinc chloride, calcium chloride, potassium chloride, potassium acetate, and potassium formate.The outcomes of this investigation are summarized in Table 7, and a visual representation of the clay swelling test for these fluids is provided in Fig. 8.As depicted in Fig. 8, the clay immersed in the potassium chloride brine exhibited minimal swelling after a 24-h period.This result aligns with expectations, as potassium chloride brine contains potassium ions, which function as inhibitors of clay swelling, a well-established practice in the drilling and completion industry 38,52 .
Furthermore, upon closer examination, the swelling index for potassium formate brine is approximately 4 cubic centimeters per 2 g of clay.Surprisingly, it was observed that this fluid induced less swelling in comparison to calcium chloride.Figure 8 also reveals the behavior of the clay when subjected to potassium acetate.The presence of potassium ions in this salt mitigated significant swelling, resulting in a swelling index of approximately 3 cubic centimeters per two grams of clay.This data strongly suggests that potassium acetate brine is effective at reducing clay swelling, outperforming other brines except for potassium chloride.In the case of zinc chloride, Fig. 8 illustrates that this brine, similar to calcium chloride, exhibits a swelling index of 4 cubic centimeters per two grams of clay.This indicates that zinc chloride does not offer a substantial advantage over calcium chloride in mitigating clay swelling.

Wettability alteration
The contact angles of different brines on carbonate and sandstone thin physical samples before and after aging (which was explained in the "Methods" section) were measured to investigate the effects of completion fluids on wettability.Aging simulated the long-term exposure of the rock to the completion fluid under reservoir the corresponding wettability status of each thin physical sample after aging.The wettability status was classified into four categories based on the contact angle values: strongly water-wet (< 70°), intermediate wettability (70°-110°), and strongly oil-wet (> 110°).
All thin physical samples were initially oil-wet before aging, as indicated by their high contact angles with kerosene.This is consistent with the common observation that carbonate rocks tend to be oil-wet or mixed-wet due to the presence of organic matter and surface-active compounds.Sandstone rocks can also exhibit oil-wet behavior depending on the mineralogy, clay content, and pore structure.Different laboratory studies have shown that, by manipulating the brine composition and reducing salt content, carbonate rock can change its wettability to a lower oil-wet state.They suggest that the driving force behind the low alkalinity effect in carbonates is likely to be surface charge modification.The sensitivity of carbonate surface charge to brine salinity, pH value, and potential ions determining brine acidity has already been established in a number of studies.But The brine chemistry has been found to play a more important role than the salt content itself in said studies 53 .The results of this study show that different brines have similar effects on the wettability of carbonate and sandstone thin physical samples.Most brines cause significant changes in wettability and are placed in the strongly water wet and intermediate wettability category.This can be attributed to the ion exchange and surface complexation mechanisms that occur between the brine components and the rock surface.The increased concentration of cations in the brine can enhance the water-wetness of the rock by displacing the adsorbed organic matter and increasing the negative charge density on the surface.In the other case, the changes are different.AC1 is when the wettability of HCOOK does not change much from oil-wet to water-wet and is placed in the strongly oil-wet category.This may be because HCOOK solution has a low pH and a high salinity, which can preserve or enhance the oil-wetness of the carbonate rock by reducing the ion exchange and surface complexation effects; or because formate brines may have an adverse effect on wettability alteration.These revelations underscore the paramount importance of selecting the appropriate completion fluid for the prevailing reservoir rock.It has the potential to exert a profound influence on wettability, subsequently impacting oil recovery efficiency.By opting for a completion fluid that can recalibrate the rock's wettability from oil-wet to water-wet, capillary forces restraining oil in the pores can be mitigated, and relative oil phase permeability can be enhanced.Conversely, choosing a completion fluid that leaves the reservoir rock's wettability unaffected or exacerbates oil-wet tendencies may hamper oil production by amplifying residual oil saturation and diminishing relative oil phase permeability.

Fluid compatibility
This critical phase of our study delves into the intricate dance of compatibility between our carefully selected completion brines, formation water, and crude oil.The acquired results, unveiled within Table 9, find visual representation in Fig. 10, offering a comprehensive understanding of this complex interplay.
The results show that all completion fluids are compatible with formation water, as no sediment formation was observed in any of the mixtures.This indicates that the completion fluids do not react with the formation water or cause any precipitation or scaling.This is desirable for maintaining the porosity and permeability of the reservoir rock.The results also show that all completion fluids are compatible with crude oil, as no sediment formation www.nature.com/scientificreports/ was observed in any of the mixtures.This indicates that the completion fluids do not interact with the crude oil or cause any emulsion or asphaltene deposition.This is beneficial for enhancing oil mobility and recovery.The only exception was sodium chloride solution, which was excluded from the investigation due to its very low density.Sodium chloride solution may not be suitable for this reservoir, as it may cause density-driven convection and fingering phenomena that can reduce the sweep efficiency and oil recovery.These findings demonstrate the potential suitability of these completion fluids for real-world reservoir applications.The compatibility of these In summary, the choice of the right completion fluid depends on the specific well and reservoir conditions at the time, considering the priority characteristics for the given application.Each solution has its own unique advantages and disadvantages, and this research provides valuable insights to guide such selection processes.

Figure 2 .
Figure 2. Graphs of the concentration of salt dissolved in water for brines.

Figure 3 .
Figure 3. Sample of corrosion coupons after and before corrosion test.

Figure 4 .
Figure 4. Brine solutions after low temperature stability test.

Figure 5 .
Figure 5. Density changes of brines with increasing temperature (after high temperature stability test).

Figure 6 .
Figure 6.pH changes of brines with increasing temperature (after high temperature stability test).

Figure 9 .
Figure 9. Wettability test of thin physical samples.

Figure 10 .
Figure 10.Before and after compatibility test samples solution.

Table 1 .
contrasts the Literature review.
Because of its optimal characteristics, 60% w.l.Potassium formate based fluid could be better suited for drilling, completion or workover applications Ahmed khan et al. 2022 Chloride based completion fluids-ionic liqud Coreflood Unlike the chloride based completion fluids, the ionic liquid based completion fluid caused almost no reduction in permeability

Table 2 .
Prepared brines and their characteristics.

Table 6 .
The evaluation of fluid corrosion.

Table 7 .
The clay swelling index of brines.